1. Field of the Invention
The present invention provides an improved method for determining the pressure and equivalent static density of drilling mud during pipe connections made in the process of drilling a well.
2. The Related Art
Wells are generally drilled to recover natural deposits of hydrocarbons and other desirable, naturally occurring materials trapped in geological formations in the earth's crust. A slender well is drilled into the ground and directed to the targeted geological location from a drilling rig at the surface. In conventional "rotary drilling" operations, the drilling rig rotates a drillstring comprised of tubular joints of steel drill pipe connected together to turn a bottom hole assembly (BHA) and a drill bit that is connected to the lower end of the drillstring. During drilling operations, a drilling fluid, commonly referred to as drilling mud, is pumped and circulated down the interior of the drillpipe, through the BHA and the drill bit, and back to the surface in the annulus. It is also well known in the art to utilize a downhole mud-driven motor, located just above the drill bit, that converts hydraulic energy stored in the pressurized drilling mud into mechanical power to rotate the drill bit. The mud circulating pumps that pump the drilling mud and thereby power the mud-driven motor are sealably connected to the surface end of the drillstring through the standpipe and a flexible hose-like connection called a kelly.
When drilling has progressed as far as the drillstring can extend without an additional joint of drillpipe, the mud circulating pumps are deactivated and the end of the drillstring is set in holding slips that support the weight of the drillstring, the BHA and the drill bit. The kelly is then disconnected from the end of the drillstring, an additional joint of drillpipe is threaded and torqued onto the exposed, surface end of the drillstring, and the kelly is then reconnected to the top end of the newly connected joint of drillpipe. Once the connection is made, the mud pumps are reactivated to power the drill motor and drilling resumes.
To isolate porous geologic formations from the wellbore and to prevent collapse of the well, the well is generally cased with tubular steel pipe joints connected together to form a casing string. Casing is set in progressively smaller diameter sections as drilling progresses. Downhole conditions and the physical properties of drilled formations determine when a section of casing must be set in order to isolate exposed wellbore. During drilling operations, the drillstring extends through the casing and into the wellbore, and rotates the drill bit against rock and geologic formations lying below the end of the hole.
The fluid pressure in porous and permeable geologic formations is generally balanced by the hydrostatic pressure in the well applied by the column of drilling mud. Pressurized drilling mud is pumped into the surface end of the drillstring by pumps that circulate mud down through the interior of the drillstring, through the BHA and drill bit and back up to the surface through the annulus. Drilling mud is designed to balance formation pressure, cool and lubricate the drillstring and drill bit, and to suspend and carry back to the surface small bits of rock called cuttings that are produced in the drilling process.
The driller generally controls hydrostatic pressures in the well by use of weighting agents added to the drilling mud to increase its density. During a pipe connection, there is no pressure applied to the drilling mud by the mud circulating pumps because the kelly is disconnected from the drillstring. As drilling progresses, additional joints of drillpipe must be connected to the drillstring at the surface to extend the reach of the drilling rig towards deeper objectives. During each pipe connection, several transients contribute to the downhole pressure. These transients are typically dynamic in nature, and the downhole pressure, (and the corresponding data representing the downhole pressure trace), comprise a continuous summation of these transients, which generally changes or fluctuates throughout the duration of each pipe connection, thereby resulting in what is referred to herein as a downhole pressure trace. Factors giving rise to transients that may contribute to or affect the downhole pressure trace during a pipe connection include:
(a) movement of the drillstring within the wellbore (rotation or reciprocation), PA1 (b) temperatures and temperature gradients throughout the wellbore, PA1 (c) pressure gradients and propagation rates of pressure fronts throughout the wellbore, PA1 (d) mud viscosity, compressibility, and other static and dynamic fluid properties of the drilling mud, and their physical sensitivities to changes in temperature, PA1 (e) drilling mud weighting agents and loading of cuttings from drilling, and uniformity or non-uniformity of dispersal of both in the mud, PA1 (f) fluid flows into and out of the wellbore, both at the surface and downhole, PA1 (g) elastic and inelastic expansion of the wellbore and casing, PA1 (h) elastic expansion and elongation of the drillstring, and PA1 (i) frictional pressure losses due to wellbore geometry and mud rheology. PA1 (a) in deep water locations, PA1 (b) as higher formation pore pressures, higher formation temperatures or formations with lower fracture pressures are encountered, PA1 (c) in extended reach wells, and PA1 (d) in wells with extremely slender boreholes with increased friction losses for required circulating mud pressures. PA1 (i) No LTB communication for at least 10 seconds, and PA1 (ii) Very low LTB voltage (e.g. LTB voltage&lt;1 Volt)
Many types of geologic formations commonly encountered in drilling will fracture and fail if subjected to excessive downhole pressure in the well. Many types of fluid-bearing geologic formations are porous or permeable, and may either flow fluid into the wellbore or accept fluids from the wellbore with fluctuations in downhole pressure. Successful drilling requires that the drilling fluid pressure remains within a mud-weight window defined by the pressure limits for wellbore stability. The lower pressure limit is either the pore pressure in the exposed formation or the limit for avoiding wellbore collapse. The upper limit is the formation fracture pressure.
If the downhole pressure during a pipe connection exceeds the formation fracture pressure, the region of the formation exposed to the downhole pressure will physically fracture and the fracture will propagate, causing drilling mud to flow from the wellbore into the fractured formation. The rate of mud loss to the fractured formation will be determined by the extent of the fracture and the pressure differential from the wellbore into the formation. The resulting loss of height of the hydrostatic column of drilling mud can quickly result in inadequate downhole pressure at the formation and a rapid loss or reversal of the pressure differential. When this occurs, formation fluids, including gases, may enter the wellbore from the fractured formation or from other formations in fluid communication with the well. This occurrence is commonly referred to as a "kick." Once introduced into the wellbore, a gas kick, for example, migrates upwardly through the drilling mud towards the surface. The upwardly migrating gas continuously expands as it encounters progressively lower pressures, often forcing drilling mud to flow out of the well either at the surface or into formations in fluid communication with the well. This is a dangerous well control situation that should be avoided, but when it happens, it must be detected early and responded to quickly.
A well control situation can also develop if the downhole pressure during a pipe connection falls below the pore pressure of fluids that reside in porous formations. This condition is commonly referred to as "underbalanced." When the well is underbalanced, fluids from porous geologic formations in fluid communication with the well will flow into the well, displacing drilling mud upwardly towards the surface. When, for example, gas is introduced into the wellbore during underbalanced conditions, it can migrate towards the surface and expand, forcing drilling mud to flow out of the well either at the surface or into formations in fluid communication with the well.
The "window of safety" or range of allowable downhole pressures during a pipe connection may be defined by the higher of the formation pore pressure or the wellbore collapse pressure (minimum) and the formation fracture pressure (maximum). The window of safety defined by these minimum and maximum pressures is narrower for wells that are developed:
Downhole instruments have been developed to provide accurate measurements of downhole pressures. Some of these instruments have a cabled connection for transmitting data back to the surface. These instruments are usually slim pieces of equipment that are run into the well inside the drillstring. Virtually unlimited amounts of real-time data can be transmitted to and used by the driller at the surface using these cabled instruments. However, most cabled instruments cannot be used during active drilling phases of the operation or without severely impairing drilling operations. The cable and the instrument must usually be fully withdrawn from the well during drilling operations, including pipe connections, when the downhole data is needed most. Cabled instruments can also be run into the well after the drillstring is removed from the wellbore, but this mode does not apply to pipe connections that occur only when the drillstring is in the well.
A mud pulse telemetry communication system for communicating data from the BHA to the surface has been developed and has gained widespread acceptance in the industry. Mud pulse telemetry systems have no cables or wires for carrying data to the surface, but instead use a series of pressure pulses that are transmitted to the surface through flowing, pressurized drilling fluid. One such system is described in U.S. Pat. 4,120,097. A limitation with mud pulse telemetry systems is that data transmission capacity, or information transmission rate, is extremely limited. Also, data gathered and/or stored downhole in bottom-hole assemblies (BHA) can only be transmitted to the surface using mud pulse telemetry when the mud circulation pumps are active and mud flow is within a certain range, i.e. during "pumps-on" operations. For example, the standard flow range for the Schlumberger 6.75-inch PowerPulse.TM. MWD Tool is 275-800 gallons per minute. During pipe connections, a "pumps-off" operation, no downhole data can be transmitted to the surface using mud pulse telemetry systems. Although many downhole pressures occurring during pipe connections can be accurately measured and stored in the BHA during the pipe connection, this data can only be transmitted via mud pulse telemetry to the surface after the circulating pumps have been turned back on, and even then, the rate of data transmission is very slow. Consequently, by the time that several pressures measured and stored in the BHA during the pipe connection are available to the driller, any well conditions arising as a result of mud loss or gas influxes occurring during the pipe connection are considerably advanced. The ability of the driller to address dangerous well conditions is irreparably harmed by the extreme delay in obtaining downhole pressure measurements made during the pipe connection. Knowing the downhole pressure trace during pipe connections could provide the driller with a valuable tool for designing and managing the drilling process. Drillers are currently without this valuable information during pipe connections, and this problem can result in well control situations that increase the cost of and compromise the success of the drilling venture.
Attempts have been made to formulate a predictor equation for use in estimating downhole conditions, including pressure, based on surface measurements. Rasmus discloses in his U.S. Pat. No. 5,654,503 a method for obtaining improved measurement of drilling conditions. Rasmus attempts to overcome the limited information transmission rate of mud pulse telemetry systems by formulating a predictor equation relating a surface condition to a related downhole condition at a given time. The Rasmus predictor equation is formulated by using a downhole instrument in the BHA to make numerous downhole measurements over a given time period. Rasmus then averages these measurements in a downhole CPU, and sends the averaged downhole condition measurement to the surface for comparison with actual related surface condition measurements.
The Rasmus method may be used to approximate downhole pressure based on surface pressure. However, the Rasmus method fails to compensate for influences from pipe movement (rotation or reciprocation), cuttings distribution, and fluid flow into and out of the wellbore, or combinations of these influences, that can cause deviations and transients in the downhole measurements. By taking an average of numerous measurements of the downhole pressure, the Rasmus method irreversibly mixes the influence of these transients into the averaged downhole value, which is then communicated to the surface for comparison to an accurate surface pressure measurement. Furthermore, the Rasmus method uses a cumbersome sequencing technique to time-shift and re-align downhole data averages with selected surface measurements.
In other words, Rasmus correlates an average taken over a given period of time, for example, 30 seconds, with a single surface measurement taken sometime during or prior to that 30-second period. Substantial inaccuracies are introduced in the averaging step and again in the time sequencing step, and these result in a poor approximation of coefficients used in the Rasmus predictor equation to reconstruct a highly sampled synthetic downhole pressure and to diagnose well conditions.
What is needed is a method of accurately estimating downhole pressures occurring during pipe connections that allows the driller to use a limited amount of strategically selected pressure data taken downhole to accurately diagnose well conditions and well behavior occurring during pipe connections. What is needed is a method of selecting and communicating only those specific downhole measurements that provide the most beneficial information for quickly and accurately diagnosing well conditions arising during pumps-off operations such as pipe connections. This method would thereby enable the driller to take appropriate remedial steps in response to adverse well conditions before a substantial problem develops.